Method for acoustic imaging of the earth&#39;s subsurface using a fixed position sensor array and beam steering

ABSTRACT

A method for seismic surveying includes disposing a plurality of seismic sensors in a selected pattern above an area of the Earth&#39;s subsurface to be evaluated. A seismic energy source is repeatedly actuated proximate the seismic sensors. Signals generated by the seismic sensors, indexed in time with respect to each actuation of the seismic energy source are recorded. The recorded signals are processed to generate an image corresponding to at least one point in the subsurface. The processing includes stacking recordings from each sensor for a plurality of actuations of the source and beam steering a response of the seismic sensors such that the at least one point is equivalent to a focal point of a response of the plurality of sensors.

CROSS-REFERENCE TO RELATED APPLICATIONS

This is a continuation in part of application Ser. No. 12/057,414 filedon Mar. 28, 2008, now U.S. Pat. No. 7,830,748 issued on Nov. 9, 2010.Priority is claimed from U.S. Provisional Application No. 60/987,784filed on Nov. 14, 2007.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The invention relates generally to the field of seismic evaluation offormations in the Earth's subsurface. More specifically, the inventionrelates to methods for determining seismic attributes in specificformations in the subsurface to a relatively high lateral and verticalresolution.

2. Background Art

Seismic surveying techniques are known in the art for determiningstructure and composition of rock formations in the Earth's subsurface.Reflection seismic techniques known in the art include deploying anarray of seismic sensors above a part of the subsurface to be evaluated.The sensor array may be deployed on the land surface, or in marinesurveys may be towed by a vessel near the surface of a body of water ormay be deployed in a selected pattern on the water bottom. The array istypically rectilinear in shape and has substantially uniform spacingbetween individual sensors in the array. A seismic energy source isdeployed near the array of seismic sensors and is actuated at selectedtimes. Signals are detected by the sensors in the array and arerecorded. The recordings are typically indexed with respect to theactuation time of the seismic energy source. The seismic signalstypically include events caused by seismic energy reflecting fromacoustic impedance boundaries in the subsurface. The time indexedrecords from each sensor are then processed to generate images of therock formations, and to evaluate their petrophysical properties such asfluid content, mineral composition and fractional volume of pore space(“porosity”).

Seismic surveying known in the art has relatively limited vertical andlateral resolution. Resolution limitations result from the fact that theEarth's subsurface functions as a low pass filter to seismic energy.Typically only relatively low frequency seismic energy is able to travelfrom the source, through the subsurface and back to the seismic sensorshaving retained enough energy to be detected above the noise. Thefrequencies are usually below 80 Hz. Images of the subsurface can beformed by summing or “stacking” of the recorded signals in variousmanners and by a process known as migration. The vertical resolutionobtained is determined by the dominant frequency associated withpenetration to the depth in the subsurface of the rock formations beinganalyzed. The lateral resolution obtained depends on the aperture sizeand sensor spacing used for the signal collection of that portion of thedata that is migrated. Various schemes are employed for the extractionof velocity versus depth and for geological interpretation. One exampleof a migration technique is described in U.S. Pat. No. 6,466,873 issuedto Ren et al.

When seismic surveys are conducted with large arrays of sensors deployedon the seabed, for example, the lateral resolution of the images formedby migration techniques will again be determined by the selected sensorarray aperture size and sensor spacing. The array aperture and sensorspacing ultimately will be limited by the cost in data processing time.Each point in the resulting images results from an aperture that hasbeen moved along a much larger array of sensors and thus the image pointis a specular point. Such fixed arrays are used for various reservoirstudies.

It is known in the art to perform seismic surveys repeatedly over a samearea of the Earth's subsurface in order to determine changes in spatialdistribution of fluids in the subsurface formations. Changes in spatialdistribution of fluid over time can result from extraction of fluids,for example, producing hydrocarbon from the formations. It is desirableto have a method for seismic surveying that provides increasedresolution as compared with techniques known in the art, for among otherpurposes, to be able to determine more precisely changes in spatialdistribution of fluids disposed in subsurface rock formation as fluidsare extracted from such formations.

SUMMARY OF THE INVENTION

A method for seismic surveying according to one aspect of the inventionincludes disposing a plurality of seismic sensors in a selected patternabove an area of the Earth's subsurface to be evaluated. A seismicenergy source is repeatedly actuated proximate the seismic sensors.Signals generated by the seismic sensors in response to detected seismicenergy, indexed in time with respect to each actuation of the seismicenergy source are recorded. The recorded signals are processed togenerate an image corresponding to at least one point in the subsurface.The processing includes stacking recordings from each sensor for aplurality of actuations of the source and beam steering a response ofthe seismic sensors such that the at least one point is equivalent to afocal point of a response of the plurality of sensors.

Other aspects and advantages of the invention will be apparent from thefollowing description and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows an example of a sensor array used for subsurface imagingaccording to the invention.

FIG. 1A shows a seismic energy source array that may be used with thearray shown in FIG. 1.

FIG. 1B shows a plurality of seismic energy sources that may be used insome examples for directed subsurface illumination.

FIG. 2 shows an example of seismic sensor distribution along one line ofan array such as shown in FIG. 1.

FIG. 3 shows a cross section of the subsurface to illustrate lateralevaluation capability of an array such as shown in FIG. 1.

FIG. 4 is a graph of seismic signal amplitude to noise ratio for variousattenuation rates with respect to frequency and acoustic energy travellength.

FIG. 5 is a graph of seismic signal to reverberation amplitude forvarious pore sizes with respect to frequency and acoustic energy travellength.

DETAILED DESCRIPTION

An objective of methods according to the present invention is to providea localized examination of subsurface Earth structures with higherresolution (both laterally and vertically) than is typically possibleusing conventional seismic surveying. In some examples, the localizedexamination may be repeated at selected times to determine changes inspatial distribution of fluids in subsurface rock formations. Variousexamples of methods according to the invention may provide such enhancedresolution examinations at depths of 1.0 km to 3.5 km below the Earth'ssurface, or in examples in marine environments within a similar range ofdistances below the water bottom. The particular examined volume withinthe Earth's subsurface to be evaluated may be selected from prior,conventional seismic surveys, for example. In methods according to theinvention relatively high frequency (as contrasted with conventionalseismic) seismic energy is used, and coherent stacking from multipleactuations of a seismic energy source is used to mitigate theattenuation of such higher frequency energy which occurs as a result ofthe acoustic properties of the subsurface rock formations. The verticalresolution of a seismic survey made according to various examples of theinvention can thus be better than that obtainable from conventionalseismic surveys.

The lateral resolution of surveys made according to the inventiondepends, as is the case for conventional seismic surveys, on theaperture size of an array of seismic sensor used. Data processingaccording to the invention, however, is relatively fast as contrastedwith convention seismic data processing because it is based on thesteering of focused beams, rather than on depth or time migrationanalysis. Methods according to the invention thus can provide theability to monitor subsurface reservoirs during production usingtime-lapse imaging, allowing a better understanding of the movement offluids in such subsurface reservoirs.

An example seismic sensor array that may be used with the invention isshown schematically at 10 in FIG. 1. In the example shown in FIG. 1, theseismic sensor array 10 may be disposed on the bottom of a body of water12 such as a lake or the ocean. The seismic sensor array 10 may includeindividual seismic sensor cables L1 through L8. The cables L1 through L8may include a plurality of spaced apart seismic sensor modules Sdisposed along the length of each seismic sensor cable L1-L8. Each ofthe seismic sensor modules S may include a so-called “four-component”seismic sensor (not shown separately). “Four-component” seismic sensorstypically include three, orthogonally oriented particle motionresponsive sensors such as geophones or accelerometers, and asubstantially collocated pressure or pressure time gradient responsivesensor such as a hydrophone. See, for example, U.S. Pat. No. 5,774,417issued to Corrigan et al. for an example of such four component seismicsensors used in a sensor cable for deployment on the bottom of a body ofwater. Examples of the longitudinal spacing between sensor modules andthe number of the sensor modules S on each seismic sensor cable L1-L8will be further explained below with reference to FIG. 2. Each seismicsensor (not shown separately) in each sensor module S may generateelectrical and/or optical signals related to the parameter beingmeasured (e.g., velocity, acceleration, pressure or pressure timegradient). The sensor signals may be communicated according to the typeof sensor output signal to a recording unit R. The recording unit R maybe disposed on the water bottom, or in a buoy near the water surface forsignal record storage and later retrieval.

A seismic energy source W, which may be an air gun array or water gunarray, or other suitable sources, such as magnetostrictive orpiezoelectric transducers may be disposed proximate the center C of thesensor array 10. The source W is actuated at selected times, and a timeindexed record of the signals produced by each sensor in each module Scan be recorded in the recording unit R for later analysis. Particularcharacteristics of the seismic energy source W will be further explainedbelow.

The seismic sensor cables L1-L8 may be arranged in a radial pattern asshown in FIG. 1. The seismic sensor cables L1-L8 in the present examplemay be symmetrically arranged about the center point C of the array 10and angularly displaced from each other by an angle of about 22½degrees. In other examples, fewer or more cables may be used than isshown in FIG. 1. It is contemplated that in such other examples theangular displacement between each of the cables will be approximatelyequal, however equal angular displacement between sensor cables is not alimit on the scope of the present invention. The radial sensor cablearrangement shown in FIG. 1 may be advantageous in calculated beamsteering of the sensor response. However, other geometric arrangementsmay be used that can be beam steered according to the invention.

FIG. 1A shows an example of the seismic energy source W in more detail.The source W may consist of a plurality of individual air guns or waterguns or other suitable seismic energy sources such as explained above,shown at W1 through W5 arranged in a small-diameter, generally circularpattern. The individual sources W1-W5 may be actuated by a sourcecontroller W6, which may be in operative communication with therecording unit (R in FIG. 1) so that the signal recordings may be timeindexed to the actuation time of the source W. In the present example,the source controller W6 may be configured to successively, individually(or in subsets or subcombinations) actuate each source W1-W5 at aselected time delay (which may be zero or any other selected time delay)after the actuation of the first one of the sources W1-W5. The timedelay may be selected such that the energy output of the array ofsources W1-W5 is oriented substantially along a selected direction. Insuch examples, the directivity of the source W may be used to furtherilluminate subsurface features identified during signal processing orotherwise. Such specific illumination will be further explained belowwith reference to FIG. 3.

Another possible implementation having even greater source focusingcapability than the example shown in FIG. 1A is shown in FIG. 1B. Theexample shown in FIG. 1B includes a first seismic energy source disposedat a first selected position being a selected radial distance from thecenter of the array 10. The example shown in FIG. 1B has such firstpositions being along each of the seismic sensor cables L1-L8. Suchseismic energy sources are shown at W2B through W17B, inclusive. Asecond seismic energy source may be placed at a second selected positionbeing a second radial distance from the center of the array 10. Theexample of FIG. 1B has these positions being along each of the sensorcables L1-L8. Such second sources are shown correspondingly at W2Athrough W17A inclusive. A seismic energy source W1A may also be disposedproximate the center of the array 10. The seismic energy sources W1Athrough W17A and W2B through W17B may be controlled by a seismic sourcecontroller similar in function to the device described above withreference to FIG. 1A at W6. In the In the example shown in FIG. 1B, theseismic sources may in combination form a steerable beam array having anaperture of about two wavelengths of the seismic energy emitted by thesources. The actuation time of the individual sources WIA through W17Bmay be selected to result in a seismic energy beam directed toward aselected subsurface location. Actuation of the sources with selecteddelay timing as above may be repeated with different time delays foreach individual source to selectively illuminate different positions inthe subsurface.

It has been determined through response simulation that using theadditional seismic sources W2A through W17B as explained above providesgood beam steering response when each first source position is about onewavelength of the seismic energy from the center of the array 10, andeach second source position is about two wavelengths from the center ofthe array 10. The arrangement shown in FIG. 1B includes having the firstand second source positions along each sensor cable L1-L8, however, thesources do not need to be so located. The seismic energy sources can belocated at any circumferential position with respect to the sensorcables.

A longitudinal spacing between seismic sensor modules on each sensorcable, and a number of such seismic sensor modules on each cable may bedetermined by the frequency range over which a seismic analysis of thesubsurface rock formations is to be performed. Such seismic frequencies,of course, must have been radiated by the seismic energy source.Selection of suitable frequency for the seismic energy source will beexplained in more detail below. The longitudinal spacing between seismicsensor modules forming the receiver array is preferably selected suchthat for a particular seismic frequency the spacing should not begreater than about one-half the seismic energy wavelength. At eachfrequency an example cable length may be about 80 to 120 wavelengths ofthe longest wavelength seismic energy frequency. Thus, it is possible touse an array having sensor cables of overall length 120 wavelengths atthe lowest frequency, but variable longitudinal spacing along each cablebetween the seismic sensor modules, so that the overall array willinclude 120 wavelength-long sensor arrays at higher frequencies with ahalf-wavelength spacing at such higher frequencies. The sound speed(seismic velocity) used to determine the wavelength is that within therock formations near the water bottom (or the Earth's surface in landbased surveys).

An example of possible longitudinal spacing between seismic sensormodules (S in FIG. 1) and numbers of such seismic sensor modules isshown schematically in FIG. 2. The seismic sensor modules (S in FIG. 1)may be more closely spaced along each cable L nearest the center point(C in FIG. 1) of the array (10 in FIG. 1), becoming more sparsely spacedtoward the longitudinal end of each cable L. In the example shown inFIG. 2, a centermost portion 10 of the cable L can be about 182 meterslong and have 160 sensor modules spaced apart from each other by about1.14 meters. Laterally adjacent on either end of the centermost portion20, a first lateral portion 22 may include 11 sensor modules spacedapart from each other by about 1.33 meters and have an overall length ofabout 15 meters. A second lateral portion 24 may be disposed laterallyadjacent each first portion 22 and have 13 sensor modules spaced about1.6 meters from each other and have overall length of about 20 meters.Respective third 26 and fourth 28 lateral portions may be adjacent asshown in FIG. 2 and include, respectively, 16 and 20 sensor modulesspaced apart by 2 and 2.67 meters, and have overall length of 32 and 53meters. Overall, each cable L in the array (10 in FIG. 1) may include280 sensor modules and have length of about 422 meters. Other lengthsand sensor module spacings may be used. It is contemplated that thesensor module spacing in the present example, when used in conjunctionwith a seismic energy source (W in FIG. 1) having substantial energy ina frequency range of about 300 to 700 Hz, will provide high resolutionimages at depths below the water bottom of 1 to 3 kilometers. Thelateral resolution of the measurements made by the array will increaseas the length and the number of sensor modules on each cable L isincreased. Vertical resolution of the measurements made by the array isrelated to the frequency content of the seismic energy.

Referring to FIG. 3, the sensor array 10 is shown disposed on the bottom12A of the body of water 12. The water top is shown at 12B. Methodsaccording to the invention may provide increased resolution images ofsubsurface formations, such as shown at 14, and may provide thecapability to image within an aperture defined by an angle shown at α inFIG. 3. It is believed high resolution images may be obtained at anglesof 45 degrees or more using methods of the present invention.

In methods according to the invention, the seismic energy source (W inFIG. 1) may be of a type to provide substantially higher frequencyenergy than is used in conventional reflection seismic surveys. As willbe explained below, in methods according to the invention the fact thatthe source W and the array 10 are stationary provides that the source Wmay be actuated repeatedly so that attenuation of higher frequencyenergy by the subsurface formations may be alleviated by summing orstacking signals from the repeated actuations.

In selecting a frequency output for the seismic energy source (W inFIG. 1) the following may be considered. A reasonable expectation forattenuation of the seismic energy as it moves through the rockformations would be about 0.1 dB attenuation per wavelength of theseismic energy as is emanates from the source (W in FIG. 1). Table 1shows a relationship between seismic energy attenuation and centerfrequency of the seismic energy, and provides guidance as to how muchsignal gain may be required at higher frequencies in order to havesimilar reflection signal strength as that of a conventional seismicsurvey. Conventional seismic surveys typically have at most about 120 Hzcenter frequency seismic energy, although in practice a more commoncenter frequency range is about 50 to 80 Hz. The attenuation to 1000 mdepth below the Earth's surface (or the water bottom) for a seismicenergy velocity of 3000 meters per second can be calculated as(2*1000*120/3000)*0.1=8 dB. To a depth of 3500 m the correspondingattenuation is about 28 dB.

TABLE 1 Gain needed for focused survey over conventional seismic survey(dB) Two way Two way Two way 1000 m 2000 m 3500 m AttenuationAttenuation Attenuation (7 dB (4 dB (2 dB Freq Wavelength to 1000 m to2000 m to 3500 m spreading spreading spreading Hz (m) (dB) (dB) (dB)gain) gain) gain) 120 25 8 16 28 200 15 13 26 46 −2 6 16 300 10 20 40 705 20 40 400 7.5 27 54 94 12 34 64 500 6 33 66 115 18 46 85 600 5 40 80140 25 60 110 700 4.3 47 94 164 32 74 134

The purpose of selecting a range of frequencies which is higher thanthat used for conventional seismic surveys, is to increase the verticalresolution and to maintain or increase the lateral resolution of theresulting seismic data while benefiting from the practical aspects ofphysically smaller sensor array apertures. Choosing a range offrequencies for which seismic data from various depths down to 3500 mand beyond can be obtained requires consideration of a number offactors. Of great importance is the attenuation rate of the seismicenergy, as suggested above. Attenuation may be quantified in dBattenuation per wavelength of energy travel. It is known in the art thatsatisfactory seismic survey results may be obtained when the attenuationis between about 0.1 and 0.16 dB per wavelength. The seismic signalreturned to the receivers (sensors) must be sufficiently high amplitudeabove the ambient noise, for example about 10 dB above the noise, forthe seismic signals to be useful for subsurface evaluation. Theforegoing relationship between the seismic signal amplitude and theambient noise is termed the signal to noise ratio and it is related tothe seismic energy source strength, the attenuation, the seismic energycenter frequency, the seismic energy bandwidth around the centerfrequency, the geometrical spreading loss, the number of receivingsensors and the prevailing ambient noise.

FIG. 4 shows a graph of one way seismic energy travel path length(related to the depth to which evaluation may be performed in thesubsurface) that will result in signal to noise ratio of 10 dB forvarious seismic energy center frequencies. Each curve in FIG. 4represents a unique value of attenuation (in dB per wavelength rangingfrom 0.08 to 0.16 in 0.02 increments). In generating the curves in thegraph in FIG. 1, the seismic energy speed was set at 2333 m/s, the beamwidth of the received seismic energy was set at 1.5 degrees, andrecordings from 1000 actuations of the seismic energy source werecombined or stacked. In a method according to the invention, because thearray (10 in FIG. 1) and the seismic energy source W are substantiallystationary as explained above, the seismic signals obtained from aplurality of actuations of the seismic source can be added together orstacked to provide gains in signal to noise.

In addition to the signal to noise ratio, another factor that must beconsidered is the signal to reverberation ratio. The desired seismicsignal is associated with the signal returned from that portion of thesubsurface environment for which the receiving array of sensors has beenfocused and steered (explained further below). At the same time as thedesired seismic signal, other signals are returned from the subsurfacedue to scatter from within a depth “shell” of thickness determined bythe bandwidth of the seismic energy and subtending a solid angledependent on the illumination and weighted in angle by the seismicsensor array beam pattern. The sum of all these signals constitutes whatis known as reverberation. FIG. 5 shows example calculations ofreverberation where the reverberation is due to scatter by pores in thesubsurface formations. As an example comparison with the graph shown inFIG. 4, at 300 Hz, for attenuation of 0.16 dB per wavelength, the signalto noise ratio for stacked signals from 1000 source actuations would be10 dB for an echo from a weak interface of impedance contrast 0.01 at adepth of 2250 m. For the same situation, FIG. 5 shows the signal toreverberation ratio would be 10 dB less than the signal to noise ratiofor scatter from pores having an average size of 7 mm. The results shownin FIG. 4 and FIG. 5 are for calculations based on simple models but areindicative of underlying fundamental limitations to the method of theinvention. The signal to noise increase provided by stacking signalsfrom repeated actuations of the source are important to the operation ofthe invention. As an example, the two-way seismic energy travel time toa formation depth of 3500 m is about 2.5 seconds for a seismic velocityof 3000 meters per second. The seismic energy source may then beactuated repeatedly every 3 seconds for a total time duration of about 3hours. The gain thus provided would be 10 log (3*60*60/3)=35 dB. If thetotal time interval is doubled to 6 hours the gain would be about 38 dB.Any further doubling of the time interval would add 3 dB. It should alsobe noted that further gain of 6 dB is provided when combined threecomponent particle motion-plus pressure-responsive sensors are used, ascontrasted with pressure-responsive sensors (hydrophones) are used aloneas explained with reference to FIG. 4.

While the signal to noise may be improved by coherent summations orstacking, the signal to reverberation may be improved by increasing thedirectivity of the source. In some examples, and as explained above withreference to FIG. 1A, a steered source may be used, designingappropriate shading procedures for the receive beam to reduce thesidelobes and by increasing the analysis bandwidth from the ⅓^(rd)octave value known in the art.

The use of prior knowledge of the velocity structure of the subsurfaceis important to successfully steer and focus the seismic sensor arraybeams. Iterative focusing strategies may be used to enhance and improvethe focusing and thereby further improve determination of the spatialdistribution of seismic properties in the subsurface.

A further application of the invention is in the investigation of theupper layers of the seabed. Placing the seismic energy sources on theseabed at various distances from the sensor array can also be used torecord and interpret surface waves. With the acoustic or elastic sourcedeployed at or near to the seabed, the wavefield will containsignificant, high-energy surface waves. These waves propagate radiallyfrom the source within the uppermost sediment layers and penetratetypically about one shear-wave length within the subsurface, and areclosely related to shear waves. As contrasted with body waves, surfacewaves exhibit distinct dispersive natures and propagation velocitieswith frequency dependencies. The occurrence of multiple surface wavemodes at particular frequencies in vertically stratified media can thenbe used to obtain an accurate geophysical model of the uppermost layersin the subsurface to a depth of tens of meters in the subsurface. Suchmodels are of great value for geohazard assessment, geotechnicalcharacterization and offshore engineering purposes, which are importantfor risk assessment and mitigation within offshore industry practices.

In addition to recording the compressional wave arrivals, the methodwill also have the capability to record shear wave arrivals. Such datacan be inverted as mentioned above and knowledge of the ratio ofcompressional to shear wave speeds is of great use in the geophysicalinterpretation.

If the source (W in FIG. 1) output for the survey arrangement shown inFIG. 1 is reasonably similar to that used in a conventional seismicsurvey, then for a depth in the subsurface of 1000 m, a frequency of 700Hz would need to have a gain of 32 dB in order to have similar signalstrength to a 120 Hz center frequency conventional seismic survey. Forpenetration depth in the subsurface to 3500 m, a frequency of 300 Hzwould need to have a gain of 40 dB over that of a conventional 120 Hzseismic survey. In a method according to the present invention, asstated above because the source (W in FIG. 1) and the array (10 inFIG. 1) are stationary, the required gain may be provided byrepetitively actuating the source (W in FIG. 1) and summing or stackingrecordings made for each actuation for each sensor in each sensor module(S in FIG. 1).

As an example, the two-way seismic energy travel time to a formationdepth of 3500 m is about 2.5 seconds for a seismic velocity of 3000meters per second. The source may then be actuated repeatedly every 3seconds for a total time duration of about 3 hours. The gain thusprovided would be 10 log(3*60*60/3)=35 dB. If the total time interval isdoubled to 6 hours the gain would be about 38 dB. Any further doublingof the time interval would add 3 dB. It should also be noted thatfurther gain of 6 dB is provided as contrasted with pressure sensors(hydrophones) used alone when vector-velocity-plus-pressure sensors areused as explained with reference to FIG. 1.

Based on the foregoing analysis, together with detailed studies of theexpected noise and reverberation for a range of frequencies, receivingarray processing schemes, available seismic source strengths anddispositions, a reasonable practical choice of the source frequency forpenetration to 1000 m below the water bottom is up to 700 Hz, while forpenetration to 3500 m the maximum frequency, depending on prevailingconditions could be as high about 300 Hz.

Four-component sensors, if such as used, provide three components of thevector acoustic intensity together with the acoustic pressure. Thus, incontrast to pressure-only sensors, each sensor has its own beam pattern,and in marine surveys in particular, allows for the significantdiscrimination against energy arriving from above the seabed. (Thisincludes the sea surface reflections of energy arriving from the seabedat earlier times.) Using velocity vector and pressure as the receivedsignals can provide, as explained above, additional 6 dB gain over theuse of pressure sensors alone in the forward direction while providingsubstantial front to back discrimination.

In a method according to the present invention, signals from the seismicsensor array 10 may be processed to focus the sensitivity of the array10 to any selected focal point (e.g., P) in the subsurface. Suchfocusing may be performed, for example, by applying a suitable timedelay to the signals recorded by each individual sensor in the array 10.The time delay may be selected, for example, such that arrival time ofseismic energy from each selected point P to each seismic sensor issubstantially identical, or may be selected to create the effect of aplane wave emanating from the focal point P. Because the spatialdistribution of seismic velocities in the subsurface may be determinedbeforehand using conventional seismic velocity analysis, the time delaymay be accurately determined prior to conducting a survey using thearray 10 or prior to processing the signal recordings. During theseismic survey technique according to the invention, a plurality ofindividual focal points may be selected throughout the area of thesubsurface that is being examined.

If during the seismic survey acquisition and/or procedure a point ofinterest (e.g., at P) is located in the subsurface, either or both ofthe following supplemental acoustic illumination procedures may beperformed. First, the time delay for operating each energy source in thesource array (see FIG. 1A and FIG. 1B) may be selected to direct theoutput of the source (W in FIG. 1) or sources (FIGS. 1A and 1B) towardthe point of interest. Alternatively, or in addition, an auxiliarysource WA may be disposed at a position on the water bottomsubstantially directly above the point of interest in order to obtainzero incidence illumination of the point of interest. The auxiliarysource WA may also be used with the seismic energy source arrangementsshown in FIG. 1A and FIG. 1B.

The method described above may be repeated at selected times in order todetermine, for example, changes in spatial distribution of fluids withinrock formations in the subsurface. Such procedure may provide higherresolution mapping of the spatial distribution than conventional “4D”seismic surveying, and may provide earlier detection of subsurfacereservoir damage such as water “coning” or unintended fluid movementresulting from permeability anistotropy.

An example data acquisition and operational method may be described asfollows. If 3D seismic data are available first it is desirable toexamine the data for an area above the subsurface volume to be analyzed.Such examination may provide a location for the sensor array (10 inFIG. 1) to be positioned.

Next the sensors in the sensor modules (S in FIG. 1) may be calibratedby transmitting seismic signals laterally along the array. Next may bedetermining the maximum and minimum directive response for sensormodule. As explained above, in some examples each sensor module mayinclude a pressure responsive sensor and a three component particlemotion responsive sensor. Directivity distribution of the sensorresponse may be determined.

After calibration of the sensors in the various modules, dataacquisition may be performed. As explained above, for certain depthranges in the subsurface and for certain desired frequency response, itmay be desirable to record signals from as many as 1,000 successiveactuations of the seismic energy source (W in FIG. 1).

Once a sufficient number of source “shots” are acquired and summed or“stacked”, the signal to noise ratio with respect to time for therecorded signals may be examined to ensure sufficient signal levels arepresent for forming beams. If the signal level is too low stacking ofsignals from individual actuations can be continued. As explained above,it is desirable to have about 10 dB signal above the noise floor

The existing 3D seismic data may also be used to estimate seismicvelocity distribution for the site. Using the 3D velocity distributionfrom seismic data, a ray tracing model of the beams steered at depth maybe initiated. The ray tracing model may correct for the influence of thenear surface formations on the beam profile. The ray modeling will showthe distortions of the beam caused by specific geology, which then canbe used to correct for the effects of a particular set of near surfaceformations.

The sensor data in the near surface time histories can be examined toidentify densely-sampled, multi-component seismic data surface waves.With the seismic energy source deployed at or near to the water bottom,the detected seismic signals (wavefield” will contain significant,high-energy surface waves. Because of the arrangement of seismic sourceand sensors as shown in FIG. 1, such surface waves may propagateradially along the directions of the “arms” of the sensor array (e.g.,sensor lines L1-L8 in FIG. 1). Such radially propagated seismic waveswithin the uppermost formation layers may be processed by analyzingtheir distinct dispersive nature. Dispersion may be processed byaccounting for changes in surface wave velocity profile because surfacewave velocities are typically frequency dependent.

Processing the occurrence of multiple surface wave modes at givenfrequencies in the vertically stratified media may be performed toobtain a highly accurate geophysical model of the shallowest formations(i.e., formation depths in a range of meters to tens of meters into thesub-surface, depending on the frequency) combining forward modeling andinversion techniques to help analyze the returns.

Because shear wave velocity is directly related to shear modulus of aparticular material, the analysis can be directed at retrievinginformation about the dynamic characteristics of the formations in thenear surface Knowledge of the overburden can be used to filter any noiseand to correct for any dominant anomaly which may influence the steeringof the beams.

In performing a method according to the invention it may be desirable toform as many beams as required to sweep a particular targeted geologicalfeature in the subsurface The resulting images and seismic attributesthus formed at a given location (at a beam focusing point or area ofinterest in the sub surface which one wishes to specifically illuminate)will have as many independent points as there are independent beamsformed.

In some examples it may be desirable to use iterative focusingstrategies to enhance and improve the focusing and thereby further ourknowledge of the geology of the environment. One example of suchiterative focusing may include illuminating specific points or areas inthe subsurface from different angles, for example by using the auxiliarysource as explained above.

To mitigate the influence of the beam's sidelobes and to improve thedetectability of reflected signal returns on the main beams, the beamsshould be shaded using routine shading techniques such as the Hannand/or Chebyshev window techniques. Such techniques are described, forexample, in, George, J., Beamforming with Dolph-Chebyshev Optimizationand Other Conventional Methods, Naval Oceanographic and AtmosphericResearch Lab, Stennis Space Center (1991). In such examples, oncespecific targeted features in the subsurface are detected it is possibleto improve the lateral definition of the beam by removing the shadinggradient applied.

As explained above with reference to FIG. 1A and FIG. 1B, the time delayfor operating each transmitter or energy source in the respective arraysmay be selected so that the output of the source is primarily directedtowards a specific point of interest.

In addition, and as explained above, an auxiliary source may be disposedat a position on the water bottom directly above a point of interest inorder to obtain near zero incidence illumination of the point ofinterest and hence augment the angular return to the receiving array. Toaugment the velocity values for various subsurface stratigraphies, theauxiliary source can be deployed at multiple selected locations. Newtimes of arrival of signals from the subsurface can be logged in. Thespecific capturing of the shear wave velocity at a geological featurecan be performed and a ratio between V_(S)/V_(P) can be produced.

In another example, after determining that a particular subsurface areais of interest, the signals from a plurality of the seismic sensors maybe multiplied, rather than summed, to increase the signal to noise ratioof the seismic signals from the area of interest. In another example,the foregoing process may be repeated in its entirety at selected timesto determine changes in properties of the subsurface formations overtime, such as movement of fluids in a subsurface reservoir. Suchmovement may be determined, as explained above herein, by determiningchanges in apparent spatial distribution of subsurface featured inferredto be a boundary between different types of fluids in the subsurface.

While the invention has been described with respect to a limited numberof embodiments, those skilled in the art, having benefit of thisdisclosure, will appreciate that other embodiments can be devised whichdo not depart from the scope of the invention as disclosed herein.Accordingly, the scope of the invention should be limited only by theattached claims.

What is claimed is:
 1. A method for seismic surveying, comprising:disposing a plurality of seismic sensors in a selected pattern above anarea of the Earth's subsurface to be evaluated; repeatedly actuating aseismic energy source proximate the seismic sensors, the sourceremaining at a fixed position during the plurality of actuations;recording signals generated by the seismic sensors indexed in time withrespect to each actuation of the seismic energy source, the seismicsensors remaining at a fixed position during the recording; andprocessing the recorded signals to generate an image corresponding to atleast one point in the subsurface, the processing including stackingrecordings from each individual sensor with other recordings from thesame individual sensors, and beam steering a response of the seismicsensors to a selected focal point of a response of the plurality ofsensors, wherein the at least one image point corresponds to theselected focal point, the image having a higher frequency content thandetectable using only a single actuation of the source.
 2. The method ofclaim 1 wherein the selected pattern comprises lines of sensors radiallyextending from a center point of an array.
 3. The method of claim 1wherein a number of seismic sensors in the selected pattern and alongitudinal spacing between seismic sensors are related to a maximumseismic energy frequency to be detected from the subsurface.
 4. Themethod of claim 1 further comprising directing energy from the seismicenergy source toward a selected point in the subsurface.
 5. The methodof claim 4 wherein the directing comprises actuating each of a pluralityof individual seismic energy sources at a time causing an output thereofto be directed substantially toward the selected point.
 6. The method ofclaim 5 wherein the selected pattern comprises lines of sensors radiallyextending from a center point of an array, and wherein selected ones ofthe seismic energy sources are disposed at selected radial positionsfrom the center point of the array.
 7. The method of claim 6 wherein theselected positions are about one wavelength from the center point andtwo wavelengths from the center point.
 8. The method of claim 7 whereinthe selected positions are along the lines of sensors.
 9. The method ofclaim 7 further comprising determining a spatial distribution of atleast one constituent of a subsurface reservoir from the processedrecorded signals, repeating the repeated actuation, recording andprocessing after a selected time period, and determining a change in thespatial distribution of at least one constituent from the repeatedprocessing.
 10. The method of claim 1 wherein the beam steeringcomprises adding a selected time delay to the recording from eachseismic sensor.
 11. The method of claim 10 wherein the selected timedelay is calculated from seismic velocity distribution determined by apreviously performed seismic survey velocity analysis.
 12. The method ofclaim 1 wherein each seismic sensor comprises three mutually orthogonalparticle motion sensing elements and a substantially collocated pressureresponsive sensing element.
 13. The method of claim 1 wherein theseismic energy source is substantially collocated with a center of theselected pattern.
 14. The method of claim 1 further comprisingpositioning an auxiliary seismic energy source substantially directlyabove a selected point in the subsurface, actuating the auxiliaryseismic energy source and recording signals generated by the seismicsensors in response thereto.
 15. The method of claim 1 furthercomprising determining a spatial distribution of at least oneconstituent of a subsurface reservoir from the processed recordedsignals, repeating the repeated actuation, recording and processingafter a selected time period, and determining a change in the spatialdistribution of at least one constituent from the repeated processing.16. The method of claim 1 further comprising using a velocitydistribution determined from seismic data, and generating a ray tracingmodel of focusing beams for the seismic sensors to a selected depth. 17.The method of claim 16 wherein the ray tracing model is used to correctfor influence of near surface formations on resultant beam profiles. 18.The method of claim 1 further comprising shading the steered beams tomitigate the influence of beam sidelobes and to improve detectability ofreflected signal returns.
 19. The method of claim 18 wherein the shadingis performed by a gradient window technique.
 20. The method of claim 18further comprising detecting specific features in the subsurface andthereafter removing applied beam shading to improve a lateral definitionof the steered beam.